Steam or fire stimulation recovery techniques are used to increase production from an oil-bearing formation. In steam stimulation techniques, steam is used to heat a section of a formation adjacent to a wellbore so that production rates are increased through lowered oil viscosities.
In a typical conventional steam stimulation injection cycle, steam is injected into a desired section of a reservoir or formation. A shut-in (or soak phase) may follow, in which thermal energy diffuses through the formation. A production phase follows in which oil is produced until oil production rates decrease to an uneconomical amount. Subsequent injection cycles are often used to increase recovery.
Steam stimulation techniques recover oil at rates as high as 80-85% of the original oil in place in zones at which steam contacts the reservoir. However, there are problems in contacting all zones of a formation due to heterogeneities in the reservoir, such as high/low permeability streaks, which may cause steam fingering. When any of these heterogeneities are present in a reservoir, the efficiency of a process begins to deteriorate due to reduced reservoir pressure, reservoir reheating, longer production cycles and reduced oil-steam ratios. As a result, steam stimulation may become unprofitable.
Various methods have been proposed so that steam can be diverted to uncontacted zones of a formation. One such method is disclosed in U.S. Pat. No. 2,402,588 which issued to Andersen. Andersen disclosed a method of filling a more permeable zone of a reservoir by injecting a dilute alkaline solution of sodium silicate under low pressure. An acid gas such as carbon dioxide is then injected to reduce the alkalinity of the solution, which results in the forming of a silica gel.
Another method is disclosed in U.S. Pat. No. 3,645,446 which issued to Young et al. Young discloses the plugging of a zone of a reservoir by injecting a mixture of steam and sodium silicate into the permeable zone. A second mixture containing steam and a gelling agent such as carbon dioxide is injected into the permeable zone and the two mixtures are allowed to react. A hard silica gel plug is formed.
Another method is disclosed in U.S. Pat. No. 3,805,893 which issued to Sarem. Sarem discloses the formation of a gelatinous precipitate by injecting small slugs of a dilute aqueous alkali metal silicate solution, followed by water and then a dilute aqueous solution of a water-soluble material which reacts with the alkali metal silicate to form a precipitate. The precipitate hardens to form a substantially impermeable substance. A water-flooding oil recovery method is then conducted in a lower permeability zone.
Christopher discloses another method in U.S. Pat. No. 3,965,986. In this method, a slug of liquid colloidal silica and water is injected into a reservoir. This slug has a relatively low viscosity. A surfactant is next injected therein which forms a gel on contact with the silica slug.
Amino resins such as melamine formaldehyde resins are cross-linked with certain polymers to make gels useful as profile control agents for high temperature reservoirs during a water-flooding operation. These gels are disclosed in U.S. Pat. No. 4,834,180 which issued to Shu on May 30, 1989. These gels are unable to withstand high temperatures encountered during a fire-flooding enhanced oil recovery operation.
Therefore, what is needed is a method for consolidating a high permeability zone of a formation while controlling the permeability of that zone with a natural silica cementing material so as to enable the conducting of an EOR method such as a steam-flooding, carbon dioxide-flooding, water-flooding or fire-flooding operation in a zone of lesser permeability where high temperatures and pH's of 7.0 or less are encountered.